Methods and apparatus for removing sections of a wellbore wall

ABSTRACT

A downhole tool may include an anchor coupled to a first portion of the downhole tool and configured to engage with a feature of a wellbore to affix the first portion to the feature. The downhole tool may also include a linear actuator coupled to the first portion and to a second portion of the downhole tool, where the linear actuator is configured to move the second portion relative to the first portion and the feature. The downhole tool may further include a cutting head coupled to the second portion and including one or more cutters configured to engage with the feature. The downhole tool may also include a control system configured to obtain remote commands to control the anchor, the linear actuator, the cutting head, or a combination thereof.

CROSS REFERENCE PARAGRAPH

This application claims the benefit of U.S. Provisional Application No.62/690,985, entitled “METHODS AND APPARATUS FOR REMOVING SECTIONS OF AWELLBORE WALL,” filed Jun. 28, 2018 and U.S. Provisional Application No.62/867,637, entitled “METHODS AND APPARATUS FOR REMOVING SECTIONS OF AWELLBORE WALL,” filed Jun. 27, 2019, the disclosure of which is herebyincorporated herein by reference.

BACKGROUND

This disclosure relates to systems and methods for performing machiningoperations within a wellbore using downhole tools.

This section is intended to introduce the reader to various aspects ofart that may be related to various aspects of the present techniques,which are described and/or claimed below. This discussion is believed tobe helpful in providing the reader with background information tofacilitate a better understanding of the various aspects of the presentdisclosure. Accordingly, it should be understood that these statementsare to be read in this light, and not as an admission of any kind.

In some cases, it may be desirable to perform machining operations on acasing or other component disposed within a wellbore. For example, itmay be desirable to machine a portion of the casing to facilitate plugand abandon operations of the wellbore. Unfortunately, it may bedifficult to effectively perform machining operations on the casing dueto spatial constraints within the wellbore.

SUMMARY

A summary of certain embodiments disclosed herein is set forth below. Itshould be understood that these aspects are presented merely to providethe reader with a brief summary of these certain embodiments and thatthese aspects are not intended to limit the scope of this disclosure.Indeed, this disclosure may encompass a variety of aspects that may notbe set forth below.

In one example, a downhole tool includes an anchor coupled to a firstportion of the downhole tool and configured to engage with a feature ofa wellbore to affix the first portion to the feature. The downhole toolalso includes a linear actuator coupled to the first portion and to asecond portion of the downhole tool, where the linear actuator isconfigured to move the second portion relative to the first portion andthe feature. The downhole tool further includes a cutting head coupledto the second portion and including one or more cutters configured toengage with the feature. The downhole tool also includes a controlsystem configured to obtain remote commands to control the anchor, thelinear actuator, the cutting head, or a combination thereof.

In another example, a wireline system includes a drum configured tospool or unspool a cable into a wellbore and a downhole tool coupled tothe cable. The downhole tool includes a linear actuator coupled to afirst portion and to a second portion of the downhole tool, where thelinear actuator is configured to move the first portion and the secondportion relative to one another. The downhole tool also includes acutting head coupled to the second portion and including one or morecutters configured to engage with a feature of the wellbore. Thedownhole tool further includes a data processing system configured toprovide instructions to control the linear actuator, the cutting head,or both.

In another example, a method includes disposing a downhole tool within acasing of a wellbore, fastening the downhole to an interior surface ofthe casing through an anchor, and rotating a cutting head having one ormore cutters relative to the casing. The method also includes forcingthe one or more cutters into the casing to machine the interior surfaceof the casing using the one or more cutters.

Various refinements of the features noted above may be undertaken inrelation to various aspects of the present disclosure. Further featuresmay also be incorporated in these various aspects as well. Theserefinements and additional features may exist individually or in anycombination. For instance, various features discussed below in relationto one or more of the illustrated embodiments may be incorporated intoany of the above-described aspects of the present disclosure alone or inany combination. The brief summary presented above is intended tofamiliarize the reader with certain aspects and contexts of embodimentsof the present disclosure without limitation to the claimed subjectmatter.

BRIEF DESCRIPTION OF THE DRAWINGS

Various aspects of this disclosure may be better understood upon readingthe following detailed description and upon reference to the drawings inwhich:

FIG. 1 is a schematic diagram of an embodiment of a wireline system, inaccordance with an embodiment of the present disclosure;

FIG. 2 is a schematic diagram of an embodiment of a downhole tool thatmay be used in a wireline system, in accordance with an embodiment ofthe present disclosure;

FIG. 3 is a schematic diagram of an embodiment of a downhole tool thatmay be used in a wireline system, in accordance with an embodiment ofthe present disclosure;

FIG. 4 is a block diagram of an embodiment of a downhole tool that maybe used in a wireline system, in accordance with an embodiment of thepresent disclosure;

FIG. 5 is a flow diagram of an embodiment of a process for operating adownhole tool of a wireline system, in accordance with an embodiment ofthe present disclosure;

FIG. 6 is a partial cross-sectional view of an embodiment of a casingthat may be deployed in a wellbore, in accordance with an embodiment ofthe present disclosure;

FIG. 7 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 8 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 9 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 10 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 11 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 12 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 13 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure;

FIG. 14 is a partial cross-sectional view of an embodiment of a featuremachined into a casing by a downhole tool, in accordance with anembodiment of the present disclosure; and

FIG. 15 is schematic diagram of an embodiment of a wellbore thatincludes multiple casings disposed therein, in accordance with anembodiment of the present disclosure.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will bedescribed below. These described embodiments are examples of thepresently disclosed techniques. Additionally, in an effort to provide aconcise description of these embodiments, all features of an actualimplementation may not be described in the specification. It should beappreciated that in the development of any such actual implementation,as in any engineering or design project, numerousimplementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which may vary from one implementation toanother. Moreover, it should be appreciated that such a developmenteffort might be complex and time consuming, but would still be a routineundertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the presentdisclosure, the articles “a,” “an,” and “the” are intended to mean thatthere are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.Additionally, it should be understood that references to “oneembodiment” or “an embodiment” of the present disclosure are notintended to be interpreted as excluding the existence of additionalembodiments that also incorporate the recited features.

With the foregoing in mind, FIG. 1 illustrates a wireline system 10 thatmay employ the systems and methods of this disclosure. The wirelinesystem 10 may be used to convey a downhole tool 12 through a geologicalformation 14 via a wellbore 16. In some embodiments, a casing 17 may bedisposed within the wellbore 16, such that the downhole tool 12 maytraverse the wellbore 16 within the casing 17. As discussed in detailbelow, a cement lining 19 may be positioned between the casing 17 andthe geological formation 14, such that the casing 17 is cemented (e.g.,affixed to) the surrounding geological formation 14. For clarity, asused herein, the casing 17 and the cement lining 19 may be referred toas respective “features” of the wellbore 16.

The downhole tool 12 may be conveyed through the wellbore 16 via a cable18 of the wireline system 10. The wireline system 10 may besubstantially fixed (e.g., a long-term installation that issubstantially permanent or modular) or may be a mobile wireline system,such as a wireline system carried by a truck. Any suitable cable 18 maybe used to convey the downhole tool 12 through the wellbore 16. Thecable 18 may be spooled and unspooled on a drum 22 of the wirelinesystem 10. In some embodiments, a power unit 24 may provide energy(e.g., electrical energy) to the wireline system 10 and/or the downholetool 12.

The wireline system 10 may include a data processing system 28 that maycontrol operations of the wireline system 10 and/or the downhole tool 12in accordance with techniques discussed herein. Indeed, as discussed indetail below, the data processing system 28 may enable autonomousoperation of the downhole tool 12 within the wellbore 16. The dataprocessing system 28 includes a processor 30, which may executeinstructions stored in a memory 32. As such, the memory 32 may be anysuitable article of manufacture that can store the instructions. Thememory 32 and may be ROM memory, random-access memory (RAM), flashmemory, an optical storage medium, or a hard disk drive, to name a fewexamples.

In the illustrated embodiment, the wireline system 10 includes wellboreequipment or pressure control equipment 38 disposed near a surface 40 ofthe geological formation 14. The pressure control equipment 38 enablesthe cable 18 to move the downhole tool 12 through the wellbore 16, whilesubstantially blocking pressurized fluid within the wellbore 16 fromleaking into an ambient environment 44 (e.g., the atmosphere). In someembodiments, the pressure control equipment 38 includes a pack-off 48that may form a fluidic seal around the cable 18. For example, the cable18 may pass through an annular opening within the pack-off 48 that mayconform to an external surface of the cable 18, thus forming the fluidseal. Accordingly, the pack-off 48 may mitigate wellbore fluids or othercontaminants, such as grease, from entering the wellbore 16 ordischarging from the wellbore 16. It should be appreciated that thepressure control equipment 38 may include any other suitable componentsor combination of components that may facilitate traversing the cable 18and the downhole tool 12 through the wellbore 16. That is, the pressurecontrol equipment 38 may additionally include, for example, alubricator, a tool trap, a pump-in-sub, a cable shearing device, one ormore motorized rollers, or any other suitable component(s).

As discussed in detail below, in some embodiments, such as during plugand abandonment operations of the wellbore 16, it may be desirable toremove a section of the casing 17 from the wellbore 16. Additionally, itmay be desirable to remove a section of the cement lining 19 surroundingthe casing 17. Accordingly, embodiments of the downhole tool 12discussed herein are equipped with a cutting head 50 that is operable toselectively remove one or more sections of the casing 17 and/or one ormore sections of the cement lining 19 from the wellbore 16.

To better illustrate the downhole tool 12 and to facilitate thefollowing discussion, FIG. 2 is a schematic of an embodiment of thedownhole tool 12. In the illustrated embodiment, the downhole tool 12includes a logging head 52 that couples the downhole tool 12 to thecable 18. In some embodiments, the logging head 52 houses a cabletension sensor and a release device. The release device may be operableto detach the downhole tool 12 from the cable 18. The cable tensionsensor and the release device may be communicatively coupled to, forexample, the data processing system 28. The downhole tool 12 may includea swivel 54 that is coupled to the logging head 52 at a first endportion 56 of the swivel 54. In some embodiments, the swivel 54 mayrotate or swivel relative to the logging head 52 (e.g., about a centralaxis 53 of the downhole tool 12). Accordingly, the swivel 54 may ensurethat components of the downhole tool 12 that are coupled to a second endportion 58 of the swivel 54 may rotate or swivel relative to the logginghead 52 without imparting a torque on the cable 18.

In the illustrated embodiment, the downhole tool 12 includes a telemetrymodule 60, also referred to herein as a control system, which is coupledto the second end portion 58 of the swivel 54. As discussed below, thetelemetry module 60 may include sensors that transmit real-time dataindicative of one or more operational parameters of the downhole tool 12to the data processing system 28. Additionally, the telemetry module 60may enable remote control of the downhole tool 12 via instructionsprovided by the processor 30 and/or an operator (e.g., a wirelineoperator) of the wireline system 10. The telemetry module 60 may becoupled to a power electronics module 66. In some embodiments, the powerelectronics module 66 may include batteries for providing electricalpower to one or more components of the downhole tool 12.

Additionally or alternatively, the power electronics module 66 maydistribute electrical power provided by the power unit 24 (e.g., via theelectrical lines embedded in the cable 18) to various sensors,actuators, motors, or other components of the downhole tool 12. In someembodiments, the power electronics module 66 may provide power (e.g.,electrical power) that is used to operate one or more hydraulic pumpsincluded in a hydraulic module 70 of the downhole tool 12. As shown inthe illustrated embodiment, the hydraulic module 70 may be coupled tothe power electronics module 66. The one or more hydraulic pumps of thehydraulic module 70 may be operable to provide a flow of pressurizedhydraulic fluid to various actuators and/or motors of the downhole tool12.

For example, as discussed below, the hydraulic module 70 may provide aflow of pressurized hydraulic fluid to a hydraulic motor of the cuttinghead 50, such that the hydraulic motor may rotate the cutting head 50about the central axis 53 of the downhole tool 12 (e.g., relative to thecasing 17). The hydraulic module 70 may also provide pressurizedhydraulic fluid to an anchor 72, a linear actuator 74, and/or one ormore centralizers 76 that may be included in the downhole tool 12.

In the illustrated embodiment, the downhole tool 12 includes acompensator 80 that may serve as a hydraulic fluid reservoir for thehydraulic module 70. Additionally or alternatively, the compensator 80may operate to provide pressure compensation to various hydraulicallyactuated components of the downhole tool 12, such as, for example, theanchor 72, the linear actuator 74, and/or the one or more centralizers76.

In some embodiments, the anchor 72 may include one or more legs 90 thatare selectively extendable from the anchor 72 in a direction thatextends generally outward (e.g., radially outward) from the central axis53 of the downhole tool 12. Accordingly, the legs 90 may engage with thecasing 17, the cement lining 19, or the geological formation 14.Particularly, in an extended position, the legs 90 may block rotationalmotion (e.g., about the central axis 53) and/or linear movement (e.g.,along the central axis 53) of the anchor 72 relative to the casing 17.The legs 90 may be transitionable between the extended position and aretracted position by regulating a flow of hydraulic fluid supplied tothe anchor 72 via the hydraulic module 70. Although the illustratedembodiment of the downhole tool 12 includes a single anchor 72, itshould be understood that, in other embodiments, the downhole tool 12may include a plurality of anchors 72 that are located at variousportions of the downhole tool 12, such as near the logging head 52and/or near the cutting head 50.

The linear actuator 74 includes a piston 100 (e.g., or multiple pistons)that may extend from or retract into a body 102 of the linear actuator74 (e.g., via regulation of a hydraulic fluid flow to the linearactuator 74). As discussed in detail below, the linear actuator 74 maytherefore enable translational movement of an upper body 104 of thedownhole tool 12 relative to a lower body 106 of the downhole tool 12.For clarity, the upper body 104 may include components of the downholetool 12 that are positioned between a lower end 108 of the linearactuator 74 and the logging head 52. The lower body 106 may includecomponents of the downhole tool 12 that are positioned between an upperend 110 of a first centralizer 111 of the centralizers 76 and thecutting head 50. In some embodiments, the piston 100 may be configuredto block rotational motion (e.g., about the central axis 53) of thelower body 106 relative to the upper body 104. Moreover, it should beappreciated that, in some embodiments, the piston 100 may house varioushydraulic lines and/or electrical lines that may provide hydraulic fluidand/or electrical power to certain components of the lower body 106,such as the centralizers 76. For example, the piston 100 may include ahollow interior region or passage that enables conduits, tubes, wires,or other connection features to extend between components of the upperbody 104 and components of the lower body 106.

The one or more centralizers 76 may be transitionable between aretracted position, in which the centralizers 76 do not engage with thecasing 17, and an extended position, in which rollers 216 of thecentralizer 76 engage (e.g., contact) a surface of the casing 17. Inother embodiments, the centralizers 76 may be passive components thatare permanently positioned in the extended position. While shown withrollers 216 in the present embodiment, in other embodiments, thecentralizers 76 may not include rollers. In any case, the centralizers76 may align the downhole tool 12 concentrically within the casing 17.The rollers 120 may enable the lower body 106 of the downhole tool 12 totranslate axially along the casing 17 while the centralizers 76 are inthe extended position. In this manner, the centralizers 76 mayfacilitate the operation of the downhole tool 12 as discussed below.

In the illustrated embodiment, the downhole tool 12 includes a motor 122and a gearbox 124 that are coupled to and positioned between thecentralizers 76. The motor 122 and the gearbox 124 are cooperativelyoperable to impart a torque on the cutting head 50 that is sufficient torotate the cutting head 50 (e.g., about the central axis 53) relative toa remaining portion of the downhole tool 12. In some embodiments, thehydraulic module 70 may supply a flow of pressurized hydraulic fluid tothe motor 122 that enables the motor 122 to drive rotation of thecutting head 50. As discussed in detail below, the cutting head 50 mayinclude one or more knives 130 (e.g., cutting tools, cutters) that areselectively extendable between a retracted position, in which the knives130 do not engage with the casing 17 and/or the cement lining 19, and anextended position, in which the knives 130 engage (e.g., contact) thecasing 17, the cement lining 19, or both. Accordingly, in the extendedposition, the knives 130 may cut into the casing 17 and/or the cementlining 19 when the cutting head 50 rotates about the central axis 53,thereby enabling the knives 130 to remove (e.g., via machining such ascutting, abrasion) a section of the casing 17 and/or the cement lining19 that is in contact with the knives 130.

FIG. 3 is a schematic diagram of another embodiment of the downhole tool12. In the illustrated embodiment, the downhole tool 12 includes a pairof cutting heads 50 (e.g., a first cutting head 182 and a second cuttinghead 184) that may be used individually or concurrently to removesections of the casing 17 and/or the cement lining 19. Indeed, it shouldbe understood that downhole tool 12 may include any suitable quantity ofcutting heads 50 that are operable to perform machining operations(e.g., cutting, grinding, drilling) on the casing 17 and/or the cementlining 19. In some embodiments, the cutting heads 50 may be driven bythe same motor 122 and the same gearbox 124. In other embodiments, eachof the cutting heads 50 may include a dedicated motor and a dedicatedgearbox that is configured to drive rotation that particular cuttinghead. For example, the second cutting head 184 may be driven by anadditional motor 186 and an additional gearbox 188.

FIG. 4 is a block diagram of another embodiment of the downhole tool 12.In the illustrated embodiment, the downhole tool 12 includes a pluralityof linear actuators 74, a plurality of anchors 72, and a plurality ofcutting heads 50. Indeed, as set forth above, it should be appreciatedthat the downhole tool 12 may include any one or combination of thecomponents discussed above, which may collectively form the downholetool 12.

To facilitate discussion of the machining operations that may beperformed by embodiments of the downhole tool 12 discussed herein, FIG.5 is a flow diagram of an embodiment of process 200 of operating thedownhole tool 12. The following discussion references element numbersused throughout FIGS. 1-4. It should be noted that the steps of theprocess 200 discussed below may be performed in any suitable order andare not limited to the order shown in the illustrated embodiment of FIG.5. Moreover, it should be noted that additional steps of the process 200may be performed and certain steps of the process 200 may be omitted. Insome embodiments, the process 200 may be executed on the processor 30and/or any other suitable processor of the wireline system 10, such as aprocessor 199 (e.g., as shown in FIG. 2) included in the downhole tool12. The process 200 may be stored on, for example, the memory 32 and/orany other suitable memory device of the wireline system 10, such as amemory 201 (e.g., as shown in FIG. 2) of the downhole tool 12.

The process 200 may begin with lowering the downhole tool 12 into thewellbore 16 via the cable 18, as indicated by block 202. For example,the cable 18 may be spooled or unspooled from the drum 22 to positionthe downhole tool 12 along a particular location in the wellbore 16. Insome embodiments, a weight of the downhole tool 12 and the cable 18 maybe sufficient to unspool the cable 18 from the drum 22 to lower thedownhole tool 12 into the wellbore 16. However, in certain embodiments,the downhole tool 12 and/or the pressure control equipment 38 may beequipped with a tractor tool (e.g., one or more motorized rollers) thatare operable to force the downhole tool 12 and/or the cable 18 into thewellbore 16 to position the downhole tool 12 along a particular locationin the wellbore 16.

The process 200 includes transitioning the anchor 72 to an engagedposition, as indicated by block 204, upon positioned the downhole to atthe desired location in the wellbore 16. For example, the hydraulicmodule 70 may receive instructions (e.g., from the processor 30) tosupply pressurized hydraulic fluid to the anchor 72, and thus, enablethe legs 90 of the anchor to transition from a retracted position to anextended position, in which the legs 90 engage (e.g., contact) thecasing 17, the cement lining 19, or another suitable portion of thewellbore 16. In this manner, the anchor 72 may block rotational motionand/or translation movement of components of the upper body 104 of thedownhole tool 12. The block 204 also includes transitioning thecentralizers 76 to respective engaged positions, such that thecentralizers 76 may center the lower body 106 of the downhole tool 12within the casing 17.

Concurrently or subsequently to instructing the anchor 72 and thecentralizers to transition to respective engaged positions, theprocessor 30 may instruct the linear actuator 74 to transition to anextended position, as indicated by block 206. For example, in someembodiments, the linear actuator 74 may be in a retracted positionedwhile the downhole tool 12 is lowered into the wellbore 16, during theblock 202. Accordingly, by transitioning to the extended position at theblock 206, the linear actuator 74 may space apart the lower body 106 ofthe downhole tool 12 from the upper body 104 of the downhole tool 12 bya distance 208 (e.g., as shown in FIG. 3). That is, the linear actuator74 may force the lower body 106 in a first direction 210 (e.g., as shownin FIG. 3) along the wellbore 16, relative to the upper body 104, whilethe upper body 104 may remain stationary relative to the wellbore 16(e.g., via a force applied by the anchor 72 to the casing 17). However,in other embodiments, the linear actuator 74 may be positioned in theextended position while the downhole tool 12 is lowered into thewellbore 16.

Next, the process 200 includes driving rotation of the cutting head 50about the central axis 53, relative to the wellbore 16, as indicated byblock 212. Particularly, the processor 30 may instruct the hydraulicmodule 70 to provide a flow of pressurized hydraulic fluid to the motor122, such that the motor 122, via engagement of the gearbox 124, maydrive rotation of the cutting head 50. As discussed below, the processor30 may adjust a rotational speed of the cutting head 50 based on knowncharacteristics of the wellbore 16 (e.g., based on a casing materialused, based on a composition of the cement lining 19) or based on sensorfeedback acquired by various sensors of the downhole tool 12.

The process 200 includes pressing the knives 130 of the cutting head 50against a surface (e.g., an interior surface) of the casing 17 toinitiate machining of the casing 17, as indicated by block 214. Indeed,the cutting head 50 may include one or more actuators (e.g., hydraulicactuators) that are operable to transition the knives 130 from aretracted position, in which the knives 130 do not engage the casing 17,to an extended position, in which the knives 130 engage (e.g.,physically contact) the casing 17. Accordingly, when engaging with thecasing 17, the rotational motion of the knives 130 about the centralaxis 53 may enable the knives 130 to machine (e.g., cut, scrape, chip)the casing 17 to remove material from the casing 17. In someembodiments, the cutting head 50 may continue to press the knives 130against the casing 17 until the knives 130 machine through a thickness(e.g., a width) of the casing 17. Therefore, the knives 130 may form acircumferential slot within the casing 17.

In some embodiments, processor 30 may instruct the cutting head 50 tomaintain a position of the knives 130 (e.g., a radial position of theknives 130 relative to the central axis 53) upon determining that theknives 130 have machined through the thickness of the casing 17. In someembodiments, the processor 30 may determine when the knives 130 havefully cut through the casing 17 based on feedback from one or moresensors monitoring a force applied by the knives 130 to the casing 17.For example, a force applied by the knives 130 to the casing 17 mayspike (e.g., suddenly increase or decrease) when the knives 130 cutthrough the casing 17 and interact with the cement lining 19 and/or thegeological formation 14 surrounding the casing 17. In other embodiments,the processor 30 may determine that the knives 130 have penetratedthrough the casing 17 based on any other one or combination ofoperational parameters of the wireline system 10.

In some embodiments, the downhole tool 12 may include a materialcollection bin 216 (e.g., as shown in FIG. 2) that is positioned beneath(e.g., with respect to a direction of gravity) the knives 130. Thematerial collection bin 216 may collect material (e.g., shavings) thatis removed from the casing 17 by the knives 130. Accordingly, theremoved material may be retrieved from the wellbore 16 by retracting thedownhole tool 12 from the wellbore 16. In other embodiments, thematerial collection bin 216 may be omitted from the downhole tool 12,such that material removed from the casing 17 may fall into the wellbore16.

The process 200 includes gradually transitioning the linear actuator 74from the extended position to the retracted position, as indicated byblock 220. In this manner, as the linear actuator 74 retracts (e.g., asthe piston 100 retracts into the body 102), the knives 130 may travelalong the casing 17 to remove additional material from the casing 17.Particularly, the knives 130 may elongate (e.g., increase an axial widthof) the circumferential slot that may be created by the knives 130 atthe block 214. In this manner, the linear actuator 74 and the knives 130may cooperate to form an elongated cutout 215 (e.g., as shown in FIG. 3)in the casing 17, in which a portion of the casing 17 is removed.Indeed, an axial length of the elongated cutout 215 may be substantiallyequal to the distance 208 upon completion of the block 220.

It should be appreciated that, in some embodiments, the knives 130 maynot cut through the entire thickness of the casing 17 at the block 214,and instead, cut through only a portion of the thickness. Accordingly,the knives 130 may cut a groove into the casing 17 at the block 214,instead of a slot. Therefore, when retracting the linear actuator 74 atthe block 220, the knives 130 may form an elongated groove that extendsalong the casing 17, instead of the elongated cutout 215.

In some embodiments, upon determining that the linear actuator 74reaches the retracted position (e.g., in which the distance 208 issubstantially negligible), the processor 30 may stop rotation of thecutting head 50, as indicated by block 222. Additionally, at the block222, the processor 30 may instruct the anchor 72 to transition to thedisengaged position, such that the legs 90 are retracted from the casing17. It is important to note that the knives 130 remain extended, andtherefore engaged with the cement lining 19, at the block 222, therebyenabling the knives 130 to temporarily support a weight of the downholetool 12 and the cable 18. That is, the engagement between the stationaryknives 130 and the cement lining 19 may ensure that the downhole tool 12does not slide down the wellbore 16 (e.g., relative to a direction ofgravity) in the first direction 210 upon retraction of the anchor 72. Insome embodiments, at the block 222, the processor 30 may temporarilyincrease a compressive force applied by the knives 130 to the cementlining 19 to enhance an engagement strength (e.g., a frictional force)between the knives 130 and the cement lining 19. In certain embodiments,the lower body 106 may include an additional anchor that is operable totemporarily support a weight of the downhole tool 12 and/or the cable 18in addition to, or in lieu of, the knives 130, while the anchor 72 isretracted.

At the block 224, the processor 30 may instruct the linear actuator 74to return to the extended position. In this manner, the linear actuator74 may force the upper body 104 of the downhole tool 12 in a seconddirection 226 (e.g., an upward direction relative to gravity, as shownin FIG. 3) by the distance 208, relative to the lower body 106. In someembodiments, at the block 224, the drum 22 may spool the cable 18 by alength that is equivalent to the distance 208, which may facilitatetranslating the upper body 104 in the second direction 226. Indeed, insome embodiments, the cable 18 may be used to provide a portion of orsubstantially all of the force that may be involved to move the upperbody 104 in the second direction 226 by the distance 208.

In any case, upon determining that the linear actuator 74 has returnedto the extended position, the processor 30 may instruct the anchor 72 totransition to the engaged position, as indicated by the block 224, toblock rotational motion and translational movement of the upper body 104relative to the wellbore 16. Additionally, at the block 224, theprocessor 30 may instruct the motor 122 to restart operation of thecutting head 50 (e.g., to drive rotation of the cutting head 50). Theprocessor 30 may again instruct the linear actuator 74 to graduallytransition from the extended position to the retracted position, asindicated by block 227, to enable the knives 130 to travel along thecasing 17 (e.g., in the second direction 226) to remove additionalmaterial from the casing 17. That is, the knives 130 may continue toelongate (e.g., increase in axial width) the elongated cutout 215 withinthe casing 17.

In some embodiments, the processor 30 may iteratively repeat the blocks222, 224, and 227 to increase an axial length of the elongated cutout215 that may be machined by the knives 130. In certain embodiments, theprocessor 30 may implement the steps of the process 200 disclosed hereinto form multiple slots and/or grooves within various sections of thecasing 17. For example, the controller 20 may repeat the blocks 202,204, 206, 212, 214, 220, 222, 224, and/or 227 at various locations alongthe casing 17 to generate multiple individual circumferential groovesand/or circumferential slots within the casing 17. In some embodiments,upon completing the desired machining operations on the casing 17, thedownhole tool 12 may be retracted from the wellbore 16, as indicated byblock 228.

In certain embodiments, the process 200 may include performingadditional machining operations on the cement lining 19 that maysurround the casing 17, as indicated by block 230. For example, in someembodiments, the downhole tool 12 may be retracted from the wellbore 16(e.g., at the block 228 to enable a wireline operator or othertechnician to replace the knives 130 with reamers 232 (e.g., cementreamers, cutters, as shown in FIG. 3) that may be tailored to moreeffectively machine the cement lining 19 than the knives 130. Indeed, itshould be appreciated that the knives 130 may include characteristics(e.g., cutting profiles, knife blade thicknesses, knife materialcompositions) that enable the knives 130 to efficiently machine ametallic material, such as the casing 17, while the reamers 232 includecharacteristics (e.g., cutting profiles, reamer blade thicknesses,reamer material compositions) that are tailored to enable efficientcutting of cement materials. However, it should be noted that, incertain embodiments, the knives 130 may be used to perform machiningoperations on both the casing 17 and the cement lining 19. Moreover, insome embodiments, the first cutting head 182 of the downhole tool 12 mayinclude the knives 130 and the second cutting head 184 of the downholetool 12 may include the reamers 232. Accordingly, the downhole tool 12may selectively operate the first cutting head 182 or the second cuttinghead 184 depending on whether the downhole tool 12 is instructed toperform machining operations on the casing 17 or the cement lining 19.

In any case, the processor 30 may perform the blocks 202, 204, 206, 212,214, 220, 222, 224, and/or 227 on the cement lining 19, instead of thecasing 17, to gradually remove material from the cement lining 19 and tomachine slots and/or grooves within the cement lining 19. For example,to perform machining operations on the cement lining 19, the processor30 may lower (e.g., via instruction sent to a motor of the drum 22) thedownhole tool 12 into the wellbore 16 via the cable 18, as indicated bythe block 202. In some embodiments, the processor 30 may position thedownhole tool 12 such that, when the linear actuator 74 is in theextended position, the reamers 232 are aligned with an initiating end233 (e.g., as shown in FIG. 3) of the elongated cutout 215. Theprocessor 30 may transition the anchor 72 to the engaged position, asindicated by the block 204, to maintain the downhole tool 12 at such alocation in the wellbore 16.

Concurrently or subsequently to instructing the anchor 72 to transitionto the engaged position, the processor 30 may instruct the linearactuator 74 to transition to the extended position and may transitionthe centralizers 76 to their respective extended positions, as indicatedby the block 206. In some embodiments, one or more of the centralizers76 may extend through the previously machined elongated cutout 215, suchthat the centralizers 76 may engage (e.g., physically contact) a portionof the cement lining 19. The processor 30 may drive rotation of thecutting head 50 (e.g., via instructions sent to the motor 122), asindicated by the block 214, and may instruct the cutting head 50 topress the reamers 232 against a surface of the cement lining 19, asindicated by the block 214. Accordingly, when engaging with thecementing lining 19, rotation of the cutting head 50 may enable thereamers 232 to machine (e.g., cut, scrape, chip) the cement lining 19 toremove material from the cement lining 19. In some embodiments, thecutting head 50 may continue to press the reamers 232 against the cementlining 19 until the reamers 232 machine through the cement lining 19 andengage with the geological formation 14. Therefore, the reamers 232 mayform a circumferential slot within the cement lining 19.

In some embodiments, processor 30 may instruct the cutting head 50 tomaintain a position of the reamers 232 (e.g., a radial position of thereamers 232 relative to the central axis 53) upon determining that thereamers 232 have machined through the thickness of the cement lining 19.The processor 30 may determine when the reamers 232 have fully cutthrough the cement lining 19 in accordance with the techniques discussedabove with respect to the machining operations that may be performed onthe casing 17.

Next, the processor 30 may instruct the linear actuator 74 to graduallytransition from the extended position to the retracted position, asindicated by the block 220, thereby enabling the reamers 232 to from anelongated cutout in the cement lining 19. For clarity, the elongatedcutout may be indicative of a section of the cement lining 19 that hasbeen removed, thereby exposing the geological formation 14 to thedownhole tool 12. Upon determining that the linear actuator 74 reachesthe retracted position (e.g., in which the distance 208 is substantiallynegligible), the processor 30 may stop rotation of the cutting head 50,as indicated by the block 222. Additionally, at the block 222, theprocessor 30 may instruct the anchor 72 to transition to the disengagedposition, such that the legs 90 are retracted from the casing 17. Thereamers 232 remain extended, and therefore engaged with the geologicalformation 14, at the block 222, thereby enabling the reamers 232temporarily support a weight of the downhole tool 12 and the cable 18.

At the block 224, the processor 30 may instruct the linear actuator 74to return to the extended position to force the upper body 104 in thesecond direction 226. Upon determining that the linear actuator 74 hasreturned to the extended position, the processor 30 may instruct theanchor 72 to transition to the engaged position, as indicated by theblock 224, and may instruct the motor 122 to restart operation of thecutting head 50, as indicated by the block 224. The processor 30 maysubsequently instruct the linear actuator 74 to gradually transitionfrom the extended position to the retracted position, as indicated bythe block 227, to enable the reamers 232 to travel along the cementlining 19 to remove additional material from the cement lining 19. Thatis, the reamers 232 may continue to elongate (e.g., increase an axialwidth of) the elongated cutout formed within the cement lining 19. Theprocessor 30 may iteratively repeat the blocks 222, 224, and 227 toincrease a length of elongated cutout and/or to form additionalelongated cutouts within the cement lining 19.

The following discussion continues with reference to FIG. 3. In someembodiments, the first cutting head 182 may be operable to rotaterespective knives 130 and/or reamers 232 in a first rotational direction240 about the central axis 53, relative to the casing 17, while thesecond cutting head 184 may be operable to rotate respective knives 130and/or reamers 232 in a second rotational direction 242 about thecentral axis 53, relative to the casing 17, which may be opposite to thefirst rotational direction 240. Accordingly, a first reaction torqueimparted by the first cutting head 182 onto the downhole tool 12 may benegated by a second reaction torque (e.g., a reaction torque in adirection opposite to the first reaction torque) imparted by the secondcutting head 184 onto the downhole tool 12. In this manner, utilizing apair of counter-rotating cutting heads 182, 184 on the downhole tool 12may reduce or substantially eliminate a resultant torque that is appliedonto the anchor 72 during operation of the cutting heads 182, 184.

As briefly discussed above, the downhole tool 12 may be equipped withone or more sensors 250 that may be communicatively coupled to, forexample, the processor 30 (e.g., and/or the processor 199), and thatprovide the processor 30 (e.g., and/or the processor 199) with feedbackindicative of one or more operational parameters of the downhole tool12. In some embodiments, the sensor feedback may enable the processor 30(e.g., and/or the processor 199) to execute some or all of the steps ofthe process 200, thereby enabling automated operation of the wirelinesystem 10.

For example, the one or more sensors 250 may include torque sensors 252that provide the processor 30 with feedback indicative of a torqueapplied by the motor 122 to the first cutting head 182, a torque appliedby the motor 186 to the second cutting head 184, or both. In someembodiments, the processor 30 may adjust operation of the motor 122and/or the motor 186 if feedback from the torque sensors 252 indicatesthat a torque applied by the motor 122 and/or a torque applied by themotor 186 deviates from a respective target value by a threshold amount(e.g., by a predetermined percentage of the target value). For example,the processor 30 may send instructions to the hydraulic module 70 toadjust a flow rate of hydraulic fluid supplied to the motor 122 and themotor 186 upon a determination that a torque applied by the motor 122and/or a torque applied by the motor 186 deviates from the respectivetarget value by the threshold amount. Accordingly, the processor 30 mayensure that the motors 122 and/or 186 operate at a desired torque rangeduring operation of the downhole tool 12.

In some embodiments, the one or more sensors 250 may include speedsensors 254 (e.g., revolution per minute sensors) that provide theprocessor 30 with feedback indicative of respective rotational speeds ofthe motor 122, the first cutting head 182, the motor 186, the secondcutting head 184, or any combination thereof. In some embodiments, theprocessor 30 may adjust operation of the motor 122 and/or the motor 186if feedback from the speed sensors 254 indicates that a rotational speedof the motor 122, the first cutting head 182, the motor 186, and/or thesecond cutting head 184 deviates from a respective target value by athreshold amount. For example, the processor 30 may send instructions tothe hydraulic module 70 to adjust a flow rate of hydraulic fluidsupplied to the motor 122 and/or the motor 186 upon a determination thatthe rotational speed of the motor 122, the first cutting head 182, themotor 186, and/or the second cutting head 184 deviates from therespective target value by the threshold amount.

In some embodiments, the one or more sensors 250 may include forcesensors 256 that provide the processor 30 with feedback indicative of aforce applied by the linear actuator 74 and/or displacement sensors 258that provide the processor 30 with feedback indicative of a displacementof the linear actuator 74 (e.g. an extension distance of the piston 100relative to the body 102). Additionally or alternatively, the one ormore sensors 250 may include force sensors 260 that provide theprocessor 30 with feedback indicative of a force applied by the anchor72 (e.g., a compressive force applied to the casing 17) and/ordisplacement sensors 262 that provide the processor 30 with feedbackindicative of a position of the legs 90 (e.g., feedback indicative ofwhether the legs 90 are in the extended or retracted positions). Incertain embodiments, the one or more sensors 250 may includeacceleration sensors 264 that provide the processor 30 with feedbackindicative of an acceleration of the downhole tool 12. The one or moresensor 250 may include vibration sensors 266 that provide the processor30 with feedback indicative of vibrations across various components orsections of the downhole tool 12. Further, the one or more sensor 250may include tensile sensors 268 that provide the processor 30 withfeedback indicative of a tension on the cable 18.

In some embodiments, the one or more sensors 250 may include forcesensors 270 that provide the processor 30 with feedback indicative of aforce applied by the knives 130 and/or the reamers 232 against thecasing 17 and the cement lining 19, respectively. Additionally oralternatively, the one or more sensors 250 may include displacementsensors 272 that provide the processor 30 with feedback indicative of anextension distance of the knives 130 and/or the reamers 232 relative toa body of the cutting head 50 (e.g., a radial dimension relative to thecentral axis 53).

In some embodiments, the one or more sensors 250 may acquire and providethe processor 30 with feedback indicative of any one or combination ofthe aforementioned operational parameters in real-time, thereby enablingthe processor 30 to adjust operating parameters of the downhole tool 12upon a determination that a particular one or the monitored operationalparameters deviates from a desired target value by a threshold amount.In some embodiments, processor 30 may iteratively execute the process200 based at least on the acquired sensor feedback from the one or moresensors 250 to automatically machine portions of the casing 17 and/orthe cement lining 19 in accordance with techniques above.

In some embodiments, the processor 30 may detect a fault condition ofthe downhole tool 12 (e.g., a loss of electrical power provided via thecable 18) upon receiving feedback from the one or more sensors 250indicating that a particular operational parameter of the downhole tool12 exceeds a threshold value. In such embodiments, upon detection of thefault condition, the processor 30 may instruct the knives 130, thereamers 232, the centralizers 76, and/or the anchor 72 to transition torespective retracted positions. Accordingly, the drum 22 may be used toretract the downhole tool 12 from the wellbore 16 upon detection of thefault, without risk of the downhole tool 12 becoming stuck in thewellbore 16 due to engagement between the knives 130, the reamers 232,the centralizers 76, and/or the anchor 72 with casing 17, the cementlining 19, and/or the geological formation 14.

FIG. 6 is a cross-sectional view of an embodiment of the casing 17 thatmay be deployed in the wellbore 16. FIGS. 7-14 are cross-sectional viewsof various embodiments of the casing 17 including different profiles ofslots 300, which may be machined into the casing via the downhole tool12 of the present disclosure. That is, the processor 30 and/or theprocessor 199 may control operation of the downhole tool 12 to machinethe slots 300 into the casing 17 (e.g., via suitable tools such as adrill, mill, reamer, or other cutter).

FIG. 15 is a schematic diagram of a wellbore 302 (e.g., the wellbore 16)that includes a multiple layers of casing disposed therein.Particularly, the illustrated embodiment of the wellbore 302 includes afirst casing 304, a second casing 306, a third casing 308, a fourthcasing 310, and a fifth casing 312 disposed within one another. Thedownhole tool 12 of the present disclosure may be used to cut one ormore slots 314 at various locations along the casings 304, 306, 308,310, and/or 312. Accordingly, well plugs may be placed into one or moreof the slots 314 to plug the wellbore 302 during a plug and abandonmentoperation.

The specific embodiments described above have been shown by way ofexample, and it should be understood that these embodiments may besusceptible to various modifications and alternative forms. It should befurther understood that the claims are not intended to be limited to theparticular forms disclosed, but rather to cover all modifications,equivalents, and alternatives falling within the spirit and scope ofthis disclosure.

1. A downhole tool, comprising: an anchor coupled to a first portion ofthe downhole tool and configured to engage with a feature of a wellboreto affix the first portion to the feature; a linear actuator coupled tothe first portion and a second portion of the downhole tool, wherein thelinear actuator is configured to move the second portion relative to thefirst portion and the feature; a cutting head coupled to the secondportion and including one or more cutters configured to engage with thefeature; and a control system configured to obtain remote commands tocontrol the anchor, the linear actuator, the cutting head, or acombination thereof.
 2. The downhole tool of claim 1, comprising aplurality of sensors configured to provide the control system withfeedback indicative of operational parameters of the downhole tool inreal-time.
 3. The downhole tool of claim 2, wherein the control systemis configured to adjust operation of the anchor, the linear actuator,the cutting head, or a combination thereof, based on the feedbackprovided via the plurality of sensors.
 4. The downhole tool of claim 3,wherein the plurality of sensors comprises at least two of: a torquesensor configured to monitor a torque applied to the cutting head via amotor of the downhole tool; a speed sensor configured to monitor anoperational speed of the motor; a force sensor configured to monitor aforce generated by the linear actuator; a displacement sensor configuredto monitor an extension length of a piston of the linear actuator; and adisplacement sensor configured to monitor an extension distance of theone or more cutters.
 5. The downhole tool of claim 1, comprising a motorconfigured to drive rotation of the cutting head to enable the one ormore cutters to remove material from the feature via a machining processto form a circumferential slot within the feature, wherein the featureis a casing positioned within the wellbore, a cement lining positionedwithin the wellbore, or both.
 6. The downhole tool of claim 5, whereinthe linear actuator is configured to translate the second portionrelative to the feature to enable the one or more cutters to removeadditional material from the casing, the cement lining, or both, as thecutting head translates along the feature.
 7. The downhole tool of claim1, wherein the linear actuator includes a piston that couples the firstportion of the downhole tool to the second portion of the downhole tool,wherein the piston includes a passageway that enables communicationlines to extend through the piston between the first portion and thesecond portion.
 8. The downhole tool of claim 1, wherein the one or morecutters include one or more cutting knives or one or more cementreamers.
 9. The downhole tool of claim 1, comprising an additionalcutting head coupled to the second portion and configured to engage withthe feature to remove additional material from the feature.
 10. Thedownhole tool of claim 9, wherein a first motor of the downhole tool isconfigured to rotate the cutting head in a first direction relative tothe feature, and a second motor of the downhole tool is configured torotate the second cutting head in a second direction relative to thefeature that is opposite to the first direction.
 11. A wireline system,comprising: a drum configured to spool or unspool a cable into awellbore; a downhole tool coupled to the cable, the downhole toolcomprising: a linear actuator coupled to a first portion and a secondportion of the downhole tool, wherein the linear actuator is configuredto move the first portion and the second portion relative to oneanother; and a cutting head coupled to the second portion and includingone or more cutters configured to engage with a feature of the wellbore;and a data processing system configured to provide instructions tocontrol the linear actuator, the cutting head, or both.
 12. The wirelinesystem of claim 11, wherein the data processing system is configured tocooperatively control the linear actuator and the cutting head to enablethe cutting head to form an elongated circumferential cutout with thefeature of the wellbore.
 13. The wireline system of claim 12, whereinthe feature includes a casing disposed within the wellbore, a cementlining disposed about the casing, or both.
 14. The downhole tool ofclaim 11, comprising at least one centralizer coupled to the secondportion of the downhole tool and configured to engage with the featureof the wellbore.
 15. The downhole tool of claim 11, wherein the downholetool comprises one or more sensors configured to provide the dataprocessing system with real-time feedback indicative of operationalparameters of the downhole tool, and wherein the data processing systemis configured to provide the instructions to control the linearactuator, the cutting head, or both, based on the real-time feedback.16. The downhole tool of claim 11, wherein the cutting head isconfigured to perform a machining operation on the feature to removematerial from the feature, and wherein the downhole tool comprises amaterial collection bin configured to capture the material removed fromthe feature.
 17. The wireline system of claim 11, wherein the dataprocessing system is configured to detect a fault condition of thedownhole tool based on feedback from one or more sensor of the downholetool and, in response to detecting the fault condition, instruct the oneor more cutters of the cutting head to transition to a retractedposition.
 18. A method, comprising: disposing a downhole tool within acasing of a wellbore; fastening the downhole to an interior surface ofthe casing through an anchor; rotating a cutting head having one or morecutters relative to the casing; and forcing the one or more cutters intothe casing to machine the interior surface of the casing using the oneor more cutters.
 19. The method of claim 18, comprising: penetratingthrough the casing with the one or more cutters to form acircumferential slot within the casing; and translating the cutting headalong the casing via a linear actuator to enable the one or more cuttersto extend the circumferential slot into an elongated cutout that extendsalong the casing.
 20. The method of claim 19, comprising: forcing theone or more cutters into a cement lining positioned about the casing tomachine the cement lining using the one or more cutters; penetratingthrough the cement lining with the one or more cutters to form anadditional circumferential slot within the cement lining; andtranslating the cutting head along the cement lining via the linearactuator to enable the one or more cutters to extend the additionalcircumferential slot into an additional elongated cutout that extendsalong the cement lining.